1. Field of the Invention
This invention relates to silyl-modified polyamide compositions. This invention also relates generally to subterranean formation treatments and, more specifically, to subterranean formation treatments employing silyl-modified polyamides to minimize migration or movement of naturally occurring or introducable solid particulates within a subterranean formation, and/or a wellbore penetrating a subterranean formation.
2. Description of the Related Art
Production of particulate solids with subterranean formation fluids is a common problem. The source of these particulate solids may be unconsolidated material from the formation (including fines), proppant from a fracturing treatment, particulate from a sand control treatment and/or fines generated from crushed fracture proppant. Production of solid proppant material is commonly known as xe2x80x9cproppant flowback.xe2x80x9d In addition to causing increased wear on downhole and surface production equipment, the presence of particulate materials in production fluids may also lead to significant expense and production downtime associated with removing these materials from wellbores and/or production equipment. Accumulation of these materials in a wellbore may also restrict or even prevent fluid production. In addition, loss of proppant due to proppant flowback may also reduce conductivity of a fracture pack.
Hydraulic fracturing is a common stimulation technique used to enhance production of fluids from subterranean formations. In a typical hydraulic fracturing treatment, fracturing treatment fluid containing a solid proppant material is injected into the formation at a pressure sufficiently high enough to cause the formation or enlargement of fractures in the reservoir. During a typical fracturing treatment, proppant material is deposited in a fracture, where it remains after the treatment is completed. After deposition, the proppant material serves to hold the fracture open, in doing so enhancing the ability of fluids to migrate from the formation to the well bore through the fracture. Because fractured well productivity depends on the ability of a fracture to conduct fluids from a formation to a wellbore, fracture conductivity is an important parameter in determining the degree of success of a hydraulic fracturing treatment.
One problem related to hydraulic fracturing treatments is the creation of reservoir xe2x80x9cfinesxe2x80x9d and associated reduction in fracture conductivity. These fines may be produced when proppant materials are subjected to reservoir closure stresses within a formation fracture which cause proppant materials to be compressed together in such a way that small particles (xe2x80x9cfinesxe2x80x9d) are generated from the proppant material and/or reservoir matrix. In some cases, production of fines may be exacerbated during production/workover operations when a well is shut-in and then opened up. This phenomenon is known as xe2x80x9cstress cyclingxe2x80x9d and is believed to result from increased differential pressure and closure stress that occurs during fluid production following a shut-in period. Production of fines is undesirable because of particulate production problems, and because of reduction in reservoir and/or fracture proppant pack permeability due to plugging of pore throats in the reservoir matrix and/or proppant pack. Fines composed of formation material (e.g., shale, sand, coal fines, etc.) may present similar problems and may be produced, for example, within a hydraulically fractured formation due to stresses and forces applied to the formation during the fracture treatment.
In an effort to control or prevent production of formation or proppant materials, many methods have been developed. Included among these are those methods commonly referred to as gravel packing and frac packs. These methods commonly employ particulate materials that are placed downhole with a gelled carrier fluid (e.g., aqueous-based fluid such as gelled brine). For example, a gravel pack operation may be carried out on a wellbore that penetrates a subterranean formation to address the production of formation particles into the wellbore from the formation during production of formation fluids. In such a method, a screen assembly may be placed within the wellbore adjacent the subterranean formation. Particulate material may be introduced with a carrier fluid into the wellbore and placed adjacent the subterranean formation by circulation so as to form a fluid-permeable pack in an annular area between the exterior of the screen and the interior of the wellbore that serves to reduce or substantially prevent the passage of formation particles from the subterranean formation into the wellbore during production of fluids from the formation, while at the same time allowing passage of formation fluids from the subterranean formation through the screen into the wellbore.
In another gravel pack method, particulate material may be introduced into a wellbore and placed opposite a formation (open hole, perforations, etc.) in the absence of a screen, and then consolidated with a curable resin (e.g., present as a self-curing coating on the particles, a curable coating on the particles that is cured with a separately introduced binding agent, etc.) or other suitable material to form a permeable consolidated mass. A core of the consolidated permeable mass may then be drilled out, leaving an annular sheath or pack of consolidated and permeable material to reduce or substantially prevent the passage of formation particles from the subterranean formation into the wellbore during production of fluids from the formation, while at the same time allowing passage of formation fluids from the subterranean formation through the screen into the wellbore, in a manner similar to that described for the gravel pack with screen. In some cases, consolidatable particulate materials may alternatively be employed in conjunction with gravel pack screens, in a manner similar to that previously described. In either case, conventional curable resins typically employed for consolidation purposes (e.g., epoxide resins) are often responsible for reduction in permeability or conductivity of the formation and/or sand control particulate pack.
In other examples, fracturing methods utilizing special types of proppants and/or additives to proppants have been employed to help form a fracture pack in the reservoir which is resistant to proppant flowback. One method of this type utilizes resin-coated proppant materials designed to help form a consolidated and permeable fracture pack when placed in the formation. Among the ways this method may be carried out are by mixing a proppant particulate material with an epoxy resin system designed to harden once the material is placed in the formation, or by the use of a pre-coated proppant material which is pumped into the formation with the fracturing fluid and then consolidated with a curing solution pumped after the proppant material is in place. Although resin-coated proppant techniques may reduce proppant flowback, they may also suffer from various problems, including incompatibility of resins with cross-linker and breaker additives in the fracturing fluid, and long post-treatment shut-in times which may be economically undesirable. Resin-coated proppants may also be difficult to place uniformly within a fracture and may adversely affect fracture conductivity. In addition, if desired, resin-coated proppants may only be added to the final stages of fracturing treatments due to their expense, resulting in a fracture pack that is consolidated only in a region near the well bore.
Recently, techniques employing a mixture of solid proppant materials designed to achieve proppant flowback control have been developed. In one technique, rod-like fibrous materials are mixed with proppant material for the purpose of causing particle bridging within a fracture proppant pack so as to inhibit particle migration and proppant flowback. This technique is believed to control proppant flowback by forming a xe2x80x9cmatxe2x80x9d of fibers across openings in the pack which tends to hold the proppant in place and limit proppant flowback during fluid production. However, in practice this method has proven to have several drawbacks, including reduction in fracture conductivity at effective concentrations of fibrous materials, and an effective life of only about two years due to slight solubility of commonly used fiber materials in brine. In addition, fiber proppant material used in the technique may be incompatible with some common well-treating acids, such as hydrofluoric acid.
In other recently developed methods, thermoplastic material in the form of ribbons or flakes is mixed with proppant material in order to form a fracture proppant pack that is resistant to proppant flowback. The thermoplastic material is designed to intertwine with proppant particles and become xe2x80x9cvery tackyxe2x80x9d at reservoir temperatures such as those greater than about 220xc2x0 F. In doing so, the materials are believed to adhere to proppant material to form agglomerates that bridge against each other and help hold proppant materials in place. In a related method disclosed in U.S. Pat. No. 5,787,986, a solution of a xe2x80x9ctackifying compoundxe2x80x9d is incorporated in intimate mixture with a particulate material and introduced into a subterranean formation. Compounds suitable for use as such a tackifying compound include compounds which when in liquid form or in a solvent solution will form a non-hardening coating, by themselves, upon the particulate. U.S. Pat. No. 5,839,510 discloses a method of treating a subterranean formation by providing a fluid suspension including a mixture of particulate material, a material including a liquid or solution of a tackifying compound, and a hardenable resin; and pumping the fluid suspension through the wellbore and depositing the mixture in the formation. U.S. Pat. No. 5,775,425 discloses a method of treating a subterranean formation by introducing a tackifying compound into a subterranean formation in a diluent containing solution to deposit upon previously introduced particulates.
Those methods employing tacky or adhesive materials to control proppant flowback suffer similar drawbacks as the fiber proppant additive method described above, most notably reduced formation or pack conductivity. Addition of separate hardenable resins increases operational complexity of well treatments and well treatment fluid formulation.
Disclosed are silyl-modified polyamide compounds that in one embodiment, may be described as substantially self-hardening compositions. In another embodiment, these compounds may also be characterized as self-crosslinking in nature. Also disclosed are methods of controlling particulate movement in wellbores and subterranean formations using well treatment fluids that include the disclosed silyl-modified polyamide compounds. Surprisingly and advantageously, when the disclosed silyl-modified polyamide compounds are introduced in the unhardened state into a subterranean wellbore and/or formation, these compounds are capable of at least partially adhering to naturally-occurring particulates or to introducable particulates that are introduced into a wellbore and/or formation, and then are further capable of self-hardening themselves to a substantially non-tacky state without the need for the presence of separate hardening components reactant components.
Because the disclosed silyl-modified polyamide compounds s elf-harden to a substantially non-tacky state, particulate movement is controlled without productivity or conductivity loss caused by formation or proppant pack pore throat blockage due to collection or accumulation of relatively small fines in pore throats. Such accumulation of relatively small fines is believed to occur due to in situ adherence of small mobile fines to conventional tacky or adhesive resin materials present in the pore throats. Further, because no separate hardening reactant components are required, well treatment fluid formulation and well treatment operations are greatly simplified over conventional multiple-component resin systems. Further surprisingly, the ultimate in situ nature of the disclosed self-hardened silyl-modified polyamide compounds may be controlled so as to be substantially non-tacky, but pliable. Advantageously, when so formulated, the pliable nature of the disclosed silyl-modified polyamide compounds may be used to absorb relatively large changes in wellbore and/or formation stresses (eg., in formations subject to high stress cycling) so as to substantially cushion particulates, thus reducing or substantially preventing fines creation while at the same time controlling particulate movement.
Thus, in one respect disclosed is a well treatment method that includes introducing a well treatment fluid including a silyl-modified polyamide compound into a wellbore penetrating a subterranean formation. The silyl-modified polyamide compound may be substantially self-hardening. In one embodiment , the well treatment fluid may include introducable particulate material suspended within the well treatment fluid, the introducable particulate material being at least partially coated with the silyl-modified polyamide in an amount effective to reduce or substantially prevent movement of at least a portion of the individual particles of the introducable particulate material when the particulates are subjected to fluid flow within the wellbore or subterranean formation; and the method may further include forming the well treatment fluid prior to introducing the well treatment fluid into the wellbore by combining a carrier fluid with the introducable particulate material that is at least partially coated with the silyl-modified polyamide to form the well treatment fluid. The method may further include applying the silyl-modified polyamide to an introducable particulate material to form the introducable particulate material that is at least partially coated with the silyl-modified polyamide, prior to combining the carrier fluid with the introducable particulate material that is at least partially coated with the silyl-modified polyamide to form the well treatment fluid.
In another embodiment, the method may further include contacting at least one of introducable or naturally occurring particulates present in at least one of the wellbore or the subterranean formation with the well treatment fluid; and the silyl-modified polyamide may be present in the well treatment fluid in an amount effective to at least partially coat and adhere to the introducable or naturally occurring particulates and to reduce or substantially prevent movement of at least a portion of the introducable or naturally occurring particulates contacted by the well treatment fluid when the particulates are subjected to fluid flow within the wellbore or subterranean formation. The method may further include allowing the silyl-modified polyamide that is at least partially coated and adhered to the introducable or naturally occurring particulates to self-harden to a substantially non-tacky state to which additional individual particulates will not adhere. The well treatment fluid may further include introducable particulate material suspended within the well treatment fluid; and the method may further include allowing the silyl-modified polyamide to contact the introducable particulate material while suspended within the well treatment fluid so as to at least partially coat and adhere to at least a portion of the introducable particulate material prior to introducing the well treatment fluid into the wellbore.
In one embodiment, the well treatment fluid may be a fracture treatment fluid; and the method may further include introducing the fracture treatment fluid into the subterranean formation at a pressure above the fracturing pressure of the subterranean formation and depositing at least a portion of the introducable particulate material into a fracture created in the subterranean formation during the well treatment. In another embodiment, the method may further include placing the introducable particulate material adjacent the subterranean formation to form a fluid-permeable pack that is capable of reducing or substantially preventing the passage of formation particles from the subterranean formation into the wellbore while at the same time allowing passage of formation fluids from the subterranean formation into the wellbore. In this regard, a screen assembly having inner and outer surfaces may be disposed within the wellbore, at least a portion of the outer surface of the screen assembly being disposed adjacent the subterranean formation; and the method may further include placing at least a portion of the introducable particulate material between the outer surface of the screen assembly and the subterranean formation to form the fluid-permeable pack. In another embodiment, the well treatment fluid may be a particulate consolidation treatment fluid containing substantially no introducable particulate material, and the method may further include allowing the silyl-modified polyamide to self-harden to substantially consolidate at least one of the introducable or naturally occurring particulate materials.
In one embodiment, introducable or naturally occurring particulate materials may subjected to stress cycling within the wellbore or the subterranean formation, and the silyl-modified polyamide may be formulated so as to self-harden to be substantially non-tacky and to have a substantially pliable in situ elastic modulus under downhole conditions so as to be capable of yielding upon particle to particle stress between individual particles of the introducable or naturally occurring particulate material that are at least partially adhered to by the silyl-modified polyamide during the stress cycling, so that an in situ creation of fines between individual particles of the introducable or naturally occurring particulate material at least partially adhered to by the silyl-modified polyamide is less than an in situ creation of fines between individual particles of the introducable or naturally occurring particulate material that are not at least partially adhered to by the silyl-modified polyamide.
In another respect, disclosed herein is a well treatment method that includes introducing a well treatment fluid into a wellbore penetrating a subterranean formation, and in which the well treatment fluid includes a silyl-modified polyamide compound that is a reaction product of a polyamide compound and a silating compound. The method may include contacting at least one of introducable or naturally occurring particulates present in at least one of the wellbore or the subterranean formation with the well treatment fluid. The well treatment fluid may include introducable particulate material suspended within the well treatment fluid that is at least partially coated with the silyl-modified polyamide in an amount effective to reduce or substantially prevent movement of at least a portion of the individual particles of the introducable particulate material when the particulates are subjected to fluid flow within the wellbore or subterranean formation, the silyl-modified polyamide may be present in the well treatment fluid in an amount effective to at least partially coat and adhere to the introducable or naturally occurring particulates and to reduce or substantially prevent movement of at least a portion of the introducable or naturally occurring particulates contacted by the well treatment fluid when the particulates are subjected to fluid flow within the wellbore or subterranean formation, or a combination thereof may exist.
In another respect, disclosed is a silyl-modified polyamide compound that may be employed in the methods disclosed herein, as well as for other purposes. In one embodiment, the silyl-modified polyamide compound may include monomeric units having a formula that is at least one of: 
a mixture thereof; and
wherein each R1 is independently an alky amine or alkyl amido-amine functional group having a terminal polyacid-based functionality; wherein each R2 is independently an alky amine or alkyl amido-amine functional group; wherein each R3 is independently an alkyl-based group having from about 1 to about 18 carbon atoms; and wherein each R4 is independently an alkoxy group having from about 1 to about 3 carbon atoms.
In another embodiment, the silyl-modified polyamide compound may include:
from about 0% to about 100% by weight of monomeric units of the formula 
from about 0% to about 100% by weight of monomeric units of the formula 
from about 0% to about 100% by weight of monomeric units of the formula 
from about 0% to about 100% by weight of monomeric units of the formula 
wherein for any given individual monomeric unit of the silyl-modified polyamide compound, (PAc) includes a polyacid-based functional group based on a polyacid having from about 2 to about 4 carboxyl functionalities. In one embodiment, for any given individual monomeric unit of the silyl-modified polyamide compound, (PAc) may include a diacid-based functional group that may be individually either one of: 
The total of all the monomeric units present in the silyl-modified polyamide compound may include about 100% by weight of the silyl-modified polyamide compound.
In another embodiment, the silyl-modified polyamide compound may include:
from about 0% to about 100% by weight of monomeric units of the formula 
from about 0% to about 100% by weight of monomeric units of the formula 
wherein for any given individual monomeric unit of the silyl-modified polyamide compound, (PAc) includes a polyacid-based functional group based on a polyacid having from about 2 to about 4 carboxyl functionalities. In one embodiment, for any given individual monomeric unit of the silyl-modified polyamide compound, (PAc) include a diacid-based functional group that may be individually either one of: 
The total of all the monomeric units present in the silyl-modified polyamide compound may include about 100% by weight of the silyl-modified polyamide compound.
In another respect, disclosed is a composition including the reaction product of a polyamide compound and a silating compound. In one embodiment, the polyamide compound may contain at least one secondary amine group, and the silating compound may include an alkoxysilane-based compound having at least one substituted reactive group capable of reacting with the at least one secondary amine group on the polyamide compound, with one or more of the silicon atoms present in each molecule of the silating compound having one or more alkoxy functionalities bonded thereto. The polyamide may include a polyamide intermediate compound that is the reaction product of a polyamine and a polyacid, the polyamine including at least three amine groups per molecule, the polyacid including from about 2 to about 4 acid functionalities per molecule; and the silating compound my include an alkoxysilane-based silating compound. The alkoxysilane-based silating compound may include at least one substituted alkyl functional group bonded to a silicon atom of the alkoxysilane-based silating compound, the substituted alkyl functional group having a terminal reactive isocyano functionality.
In another embodiment, the polyamine may include a polyamine having from about 1 to about 4 secondary amine groups per molecule and may be at least one of an polyalkylene polyamine, aromatic polyamine, or mixture thereof; the polyacid may include at least one of a dimer acid having from about 16 to about 36 carbon atoms, a trimer acid having from about 24 to about 54 carbon atoms, or a mixture thereof; and the alkoxysilane-based silating compound may have from about 1 to about 3 alkoxysilane functionalities bonded to a silicon atom of the alkoxysilane-based silating compound, each of the alkoxysilane-based functionalities including an oxygen atom bonded to the silicon atom and to a terminal alkyl chain having from about 1 to about 18 carbon atoms.
In another embodiment, the polyamine may include at least one of diethylene triamine, triethylene tetraamine, pentaethylene hexamine, or a mixture thereof; the polyacid may include a diacid having the formula: 
the alkoxysilane-based silating compound may include a compound having the formula:
Oxe2x95x90Cxe2x95x90Nxe2x80x94R3xe2x80x94Sixe2x80x94(R4)3
wherein R1 is an alkyl-based group having from about 1 to about 18 carbon atoms; and each R4 is independently an alkoxy group having from about 1 to about 3 carbon atoms.
In another embodiment, the polyamine may include at least one of diethylene triamine, triethylene tetraamine, pentaethylene hexamine, or a mixture thereof; the polyacid may include a diacid having the formula: 
the alkoxysilane-based silating compound may include at least one of gamma-isocyantomethyltriethoxysilane, gamma-isocyantopropyltriethoxysilane, 3-aminopropyltriethoxysilane, or a mixture thereof.
In another embodiment, the polyamine may include at least one of diethylene triamine, triethylene tetraamine, pentaethylene hexamine, or a mixture thereof; the alkoxysilane-based silating compound may include a compound with the formula: 
the polyacid may include at least one of: 
a mixture thereof.